The present invention relates to the field of flow meters for multiphase mixtures. In particular, the invention relates to flow meters for oil and water mixtures in hydrocarbon wells.
The measurement of oil and water flow rate in each producing zone of an oil well is important to the monitoring and control of fluid movement in the well and reservoir. In addition to a flow meter, each zone may have a valve to control the fluid inlet from that zone. By monitoring flow rates of oil and water from each zone and reducing flow from those zones producing the highest water cut (i.e., ratio of water flow rate to total flow rate), the water production of the entire well can be controlled. This, in addition, allows the reservoir oil to be swept more completely during the life of the well.
To evaluate the water and hydrocarbon flow rates in homogeneous flows in a well, three quantities must be estimated, namely, the mean water volume fraction Hw, the mean water velocity vw, and the mean hydrocarbon velocity vo. The flow rates are then as follows:
qw=AHwvwxe2x80x83xe2x80x83[1]
for the water; and
qo=A(1xe2x88x92Hw)voxe2x80x83xe2x80x83[2]
for the hydrocarbon, where A is the section of the well.
When the flow is not homogeneous, which is possible in deviated wells, flow-rate evaluations based on the above equations are invalid. It is then necessary to take account of the effective distribution of the velocities and of the volume fractions across the section of the well. In order to adopt such an approach, it is necessary that a plurality of devices are placed across a given cross-section of the well.
It is also known that the velocity of a flow in a well can be determined by measuring a magnitude that varies over time s1(t) and s2(t) at two different locations in the well separated in the direction of flow, and then by calculating a cross-correlation function:
C= less than s1(t)*s2(t+T) greater than xe2x80x83xe2x80x83[3]
In a two-phase fluid, the fluctuations in the magnitude s(t) may, for example, be due to inhomogeneous structures propagating along the pipe at the mean speed of the flow.
If T is the value of t found for which C is a maximum, the speed v of the flow is given by:
v=L/Txe2x80x83xe2x80x83[4]
where L is the axial distance between the two measurement sections.
Ideally, a flow meter for making such measurement in a well should satisfy several criteria: 1) it should be extremely reliable and operate for long periods at downhole temperature and pressure; 2) it should operate in both stratified (near-horizontal) and dispersed flow regimes over a wide range of total flow rate and cut; 3) it should not require that the well completion be oriented azimuthally in any particular way during installation; 4) it should not require the use of radioactive sources: and 5) the flow meter should allow small changes in water cut and flow rate to be detected.
Typically, downhole flow meters determine the holdup (volume fraction of oil or water) and the velocity of the oil phase, the water phase, or both. The flow rate of water is then determined from the product of water holdup xcex1w, the pipe area A, and the velocity of water UW. An analogous relation holds for oil flow rate. In general, the velocities of water and oil are different. The slip velocity (difference in oil and water velocities) depends on many parameters, such as the inclination angle of the flow pipe (i.e. deviation), roughness of the pipe wall, and flow rates of the two phases. In general, one must measure the holdup and velocities of both oil and water to determine oil and water flow rate uniquely. In practice, sometimes one measures the velocity of only one phase and uses a theoretical or empirically determined slip law to obtain the other. This has a number drawbacks including inaccuracies due to differences conditions used as inputs to the model and the actual conditions downhole.
A common method to determine the velocity of a fluid is to measure the rotation rate of a spinner in the flow stream. In single phase flow, the rotational velocity of the spinner is simply related to the velocity of the flow. However, in mixed oil and water flow the response of the spinner can be so complicated as to be impossible to interpret.
Another method of velocity measurement uses tracers. A tracer is injected into the phase of choice (oil or water) and, at a known distance downstream, a sensor detects the time of passage of the tracer. The velocity is computed from the known distance and time of travel. One disadvantage of the tracer method for permanent downhole use is the need for a reservoir of tracer material and a mechanical tracer injector. The reservoir limits the number of measurements and the injector, being a mechanical device, is prone to sticking and failure.
Another method of velocity measurement uses a Venturi. In single phase flow, a Venturi generally obeys the Bernoulli equation which relates volumetric flow rate Q to fluid density xcfx81 and pressure drop from the inlet to the throat of the Venturi:                     Q        =                  C          ⁢                                                    2                ⁢                Δ                ⁢                                  xe2x80x83                                ⁢                                  p                  /                  ρ                                                            (                                                      1                                          A                      throat                      2                                                        -                                      1                                          A                      inlet                      2                                                                      )                                                                        [        5        ]            
where C is the discharge coefficient which is approximately unity but depends on the geometry of the Venturi, xcex94p is the pressure drop from Venturi inlet to throat, and Athroat and Ainlet are the throat and inlet cross sectional areas, respectively. The same equation can be used to determine the combined oil and water flow rate where the density in this case is the average mixture density in the throat of the Venturi. In practice, the square root in the equation makes it relatively insensitive to errors in both the density and pressure determinations.
A common method to determine the holdup in a flow of oil and water is to measure the average density of the fluid. Since oil at downhole pressure and temperature typically has a density which is smaller than that of water (around 0.7 g/cm3 compared to 1.0 g/cm3), the oil and water holdups xcex1o and xcex1w can be determined proportionately from the mixture density by the relations                               α          o                =                                            ρ              w                        -                          ρ                              m                ⁢                                  xe2x80x83                                ⁢                i                ⁢                                  xe2x80x83                                ⁢                x                                                                        ρ              w                        -                          ρ              o                                                          [        6        ]                                          α          w                =                                            ρ                              m                ⁢                                  xe2x80x83                                ⁢                i                ⁢                                  xe2x80x83                                ⁢                x                                      -                          ρ              o                                                          ρ              w                        -                          ρ              o                                                          [        7        ]            
A common method to determine the mixture density is to measure the hydrostatic pressure of a column of fluid with a gradiomanometer. This device relies on having a component of the gravitational force vector along the axis of the flow pipe. This type of device, however, fails when the flow pipe is horizontal because the gravitational force vector is perpendicular to the pipe axis.
It is also known, e.g. from U.S. Pat. No. 5,017,879 or FR 2 780 499, that capacitive devices can be used to determine the characteristics of multi-phase flows. The dielectric constant of a mixture of fluids depends on the respective fraction of each of its components and on their individual dielectric constants. It has thus been proposed to estimate the composition of a two-phase fluid on the basis of its dielectric constant.
The dielectric constant is itself obtained by exciting the fluid by means of electrodes separated by the fluid, in particular electrodes placed on the pipe, and across which an AC voltage is applied. The measured magnitude is the resulting current. Guard electrodes have also been added to maintain the electrostatic field between the active electrodes. It is thus easier to interpret the measurements by limiting the edge effects due to the finite length of the active electrodes, or by focusing the electric field in a particular zone of the flow.
In both of the above-mentioned cases, namely when the flow is not homogeneous, or when the velocity is measured, it is thus necessary to dispose a plurality of devices, in particular capacitive devices, close together on the pipe. Contradictory requirements then have to be faced.
It is desirable to use devices that are of small size. In a non-homogeneous flow, better resolution in space is thus obtained, thereby considerably improving the speed and the accuracy of the interpretation algorithm. When velocity is to be measured, the small size of the devices makes it possible to position them closer together, and thus to obtain a correlation peak that is clearer for the resulting measurements, because the inhomogeneous structures deform to a lesser extent between the two devices. Unfortunately, such a small size generally makes the measurements much more sensitive to electromagnetic noise. When the measurements are capacitive measurements, the measured capacitance values are low. Typically, the currents induced by the stray capacitance may be greater by several orders of magnitude than the current resulting from the capacitance to be measured. The stray capacitance thus gives rise to a systematic error or bias whose variations can exceed the amplitude of the signal itself.
Flow measurement devices are also known that comprise a segment of insulating pipe and means for generating an electric current in the fluid flowing in said pipe. These devices thus complement the preceding devices since they apply to multiphase fluids having a continuous conductive phase, i.e. fluids that are not insulating.
The difficulty with such devices lies in measuring the potential difference between two points of the fluid to deduce the electrical resistance between those two points, given knowledge of the current. Thereafter, the resistance is used to deduce the mean resistivity given that the shape of the pipe is known.
Mixers of various types have been used to mix the oil and water, so as to effectively reduce the slip and allow for more accurate determination of the flow rates. Some mixers are simply small orifices in plates of suitable material. Others comprise more elaborate fins having certain twists or curled shapes. There are a number of disadvantages, however, in using conventional mixers when trying to measure the flow rates of oil and water downhole. For example, the mixer often obstructs the borehole, such that it may be difficult to pass certain equipment such as production logging tools, etc. Mixers also can produce unacceptable amounts of pressure loss. Additionally, mixers are prone to excessive wear with age.
It is possible to measure the pressure differential upstream and downstream of a conventional mixer in an attempt to determine the total flow rate of oil and water. This technique, however, has a number of drawbacks. For example, the accuracy of the flow rate determined by this method is likely to be much lower than using a Venturi, and, in general, greatly dependent upon the flow rates. Using a mixer to measure pressure differential can also lead to inaccuracy due to sensitivity to the exact location of pressure measurement. Using a conventional mixer in this fashion would also be prone to problems associated with wear. For example, in an orifice mixer, the relationship between the pressure differential and the velocity could change significantly over time due to slight changes in shape and size of the orifice caused by wear.
U.S. Pat. No. 4,856,344, issued to Hunt, discloses using a Venturi for obtaining a pressure differential and using a gradiomanometer upstream and through the Venturi to measure density. Hunt discloses using an iterative process to estimate the relative flow velocities. Hunt also discloses using a separate upstream step discontinuity to mix the fluids upstream of the gradiomanometer. However, the method disclosed in Hunt is prone to problems associated with relying on estimates of the flow velocities (i.e. a slip model), using separate additional mixers upstream, and using a gradiomanometer (e.g. nonfunctional when pipe is horizontal, and low accuracy when near-horizontal).
U.S. Pat. No. 5,361,632, issued to Magnani, discusses a holdup measurement using a combination of gradiomanometer and gamma-ray densitometer. Thus, the method of Magnani is prone to problems associated with using a gradiomanometer which is not suitable for measurements in near-horizontal pipes. Furthermore, the method obstructs the borehole and would not be suitable for permanent installation.
U.S. Pat. No. 5,661,237, issued to Dussan et al. discusses a holdup measurement using local probes. There is no mention of a Venturi, however. The method obstructs the borehole and would not be suitable for permanent installation.
U.S. Pat. Nos. 5,893,642 and 5,822,390, issued to Hewitt et al. disclose a method of using a mixer to measure flow rates. However, this method suffers from the disadvantages of using a mixer as described above. For example, the mixer obstructs borehole and is not suitable for permanent installation due to problems of wear.
The present invention provides a flow meter for multiphase flows, comprising a holdup measuring device having a Venturi located upstream thereof and separated therefrom by a distance that results in flow through the holdup measuring device being at least partially homogenized by the effect of the Venturi on the fluids flowing therethrough.
Preferably, the holdup measuring device is a capacitive device and/or a resistive device. It is particularly preferred that the holdup measuring device measures volume fractions in the range of 0-100% water. Such a device can be provided by a combination of capacitive and resistive measurements on the flowing fluids.
Preferred capacitive sensors for determining the characteristics of multi-phase flows are of small size and substantially insensitive to noise and thus substantially free from systematic error. A particularly preferred sensor comprises at least one excitation electrode provided with at least one cutout in which at least one measurement electrode is disposed, the electrodes being applied against the pipe.
A device for measuring the dielectric constant of a multi-phase fluid flowing along a pipe comprises at least one sensor as described above, means for maintaining the electrodes at the same potential and for measuring the current output by the measurement electrode, and means for deducing the dielectric constant from the current.
This configuration then makes it possible for all of the conductors liable to give rise to interference that are situated in the vicinity of the device in the detection system to be maintained at the potential of the excitation electrode. As the conductors are at the same potential as the measurement electrode, the load thereon thus depends only on the potentials applied to the active electrodes.
In a first embodiment, the excitation electrode is connected to the general ground of power supply means. This approach is relatively simple.
In another embodiment, the excitation electrode constitutes a floating ground for the current measuring means. The advantage of this embodiment is that the signal can be amplified to a level at which it dominates the common mode rejection voltage of the amplifier. In this embodiment, the current measuring may comprise a first amplification stage referenced relative to the potential of the excitation electrode, and a second amplification stage arranged to bring the reference of the output signal to the general ground. More particularly, the device may include shielding electrically connected to the excitation electrode, around the measurement electrode and around said first amplification stage. Such a configuration does not require the first amplification stage to be located in the immediate vicinity of the measurement electrode. The shielding of the measurement electrode may be extended by a shielded cable along which a conductor passes that connects the measurement electrode to the amplification means which are themselves provided with shielding forming the following portion of the shielded cable. The excitation electrode may overlap the measurement electrode.
The resistivity measuring device preferably comprises a pipe segment of insulating material and means for generating an electric current in the fluid flowing along the pipe, the device being characterized by the fact that it comprises two measurement electrodes spaced apart in the axial direction of the insulating segment to determine the electrical resistance of the fluid between the two electrodes, the measurement electrodes being applied to the outside of the wall of the segment to perform measurement by capacitive coupling, and by the fact that it further comprise measurement means for measuring the voltage between the measurement electrodes.
The measurement can thus be treated as a xe2x80x9c4-pointxe2x80x9d resistance measurement.
Since this arrangement is not dependent on the contact impedance between the fluid and the upstream and downstream metal portions of the pipe, the surface state of the pipe has no effect on the measurement. Furthermore, no measurement electrode comes into contact with the fluid. There is thus no risk of corrosion. This characteristic makes the device of the invention particularly suitable for continuous, long term measurements. It is thus possible to fit a production tube with measurement segments of the invention at the levels of the fluid inlets, and thus monitor the actual production of each production zone in a hydrocarbon well. The device is also suitable for performing continuous measurements on the surface, in particular at a well head.
In a particular embodiment, the measurement electrodes are annular electrodes placed around the insulating pipe segment. Also, a guard electrode may surround each of the measurement electrodes.
More particularly, the measurement means for measuring the voltage between the measurement electrodes may be arranged to maintain the voltages of the guard electrodes at the same values as the voltages of the corresponding measurement electrodes.
The measurement means for measuring the voltage between the measurement electrodes may also be arranged so that the current flowing between the measurement electrodes is small enough to avoid affecting the measured voltage. Thus, the potential difference between the two electrodes is equal to the potential difference between the points in the fluid facing the electrodes.
In this case, the measurement means for measuring the voltage between the measurement electrodes may comprise respective follower amplifiers associated with each of the measurement electrodes, each amplifier having one of its inputs connected to a measurement electrode and its other input connected to the corresponding guard electrode and having its output connected to the guard electrode, the device further comprising means for determining the potential difference between the outputs of the two follower amplifiers. Such a follower amplifier possesses high input impedance which avoids the potential drop due to current passing through the insulation by the capacitive effect. Its output voltage is equal to the input voltage, but current is available at its output. More particularly, each follower amplifier may be connected to the corresponding measurement electrode by the core of a coaxial cable, and to the corresponding guard electrode by the shield of the cable.
In a particular embodiment, the means for generating an electric current in the fluid flowing in the pipe comprise a toroidal emitter coil surrounding the tubing and a return electrical conductor interconnecting metal portions of the pipe situated respectively upstream and downstream from the insulating segment. Such a coil has the advantage of not coming into contact with the fluid, and thus of being unaffected by corrosion problems. The emitter coil, connected to an AC voltage generator, generates an electric field in the fluid and thus behaves like a primary winding of a transformer whose secondary winding is constituted by the fluid and the return conductor. This electric field generates the above-specified current, which depends on the resistance of the fluid.
It is also preferred that the device of the invention comprises a toroidal receiver coil surrounding the tubing to form a current measuring system. Each receiver coil is connected to an electronic circuit having low input impedance. The output from the electronic circuit delivers a signal that is proportional to the current flowing in the fluid. In this case, the device may comprise means for determining the ratio between the output from the voltage-measurement means for measuring the voltage between said measurement electrodes and the output from the current-measuring system. This ratio is proportional to the resistance of the fluid, ignoring contact impedance.
The invention therefore provides a device for determining the volume fraction (or xe2x80x9choldupxe2x80x9d) of the conductive fluid in a multiphase fluid having a continuous conductive phase comprising a device of the type described above to measure the mean resistivity of the multiphase fluid, and means for deducing the volume fraction from the resistivity.
Determining the volume fraction requires not only knowledge of the mean resistivity, but also knowledge of the resistivity of the conductive phase and of the flow conditions. The resistivity of the conductive phase can be determined by other means, and it is possible to make various assumptions about the flow conditions or again, they can be measured directly.
In a particular embodiment of the invention, a Venturi total volumetric flow rate measurement is provided with a holdup measurement approximately 1-10 pipe diameters downstream of the Venturi. The invention makes use of a flow instability downstream of the Venturi throat. When the oil and water flow accelerates into the throat of the Venturi, the streamlines converge from their upstream value and the pressure drops as the hydrostatic head is converted into kinetic energy. Conversely, as the flow enters the diffuser section the pressure recovers as the flow decelerates. This adverse pressure gradient can lead to separation of the flow within the boundary layer at some position downstream of the throat of the Venturi. That position depends on the geometry of the Venturi, the individual oil and water flow rates, the deviation angle of the pipe to the horizontal, and the densities of the two fluids. The main flow expands beyond the Venturi as a jet of approximately uniform velocity bounded by a free shear layer, and such shear layers are prone to Kelvin-Helmholtz type instabilities that grow and are convected downstream. In the diffuser of the Venturi, an instability such as this grows and perturbs the interface between the two fluids. The amplitude of the instability depends on the geometry of the Venturi, the deviation of the pipe, the densities of the fluids, and the flow rates. An instability of sufficient strength causes the interface to roll up and break with a resulting mixing of the two layers completely across the pipe.
According to the invention, a method of determining the flow rate of a first fluid phase in a pipe containing at least two fluid phases is provided. The fluid phases flow through an upstream pipe, a constriction, which is preferably a Venturi, and a downstream pipe. The differential pressure of the fluid phases is measured such that it can be related to the total flow rate of the fluid phases through the section of pipe. The differential pressure is preferably measured between the upstream pipe and the throat of the Venturi. The volume fraction of the first fluid phase (preferably water) is determined by making a measurement at a location downstream of the constriction where a substantial amount of mixing of the at least two fluid phases is present, which results from the fluid passing through the Venturi. The flow rate of the first fluid (preferably water) is determined by assuming its velocity is substantially the same as that of the other fluid phases.
The present invention can provide a flow meter suitable for downhole placement that is extremely reliable and capable of operating for years at downhole temperatures and pressures. It can be capable of operating in both stratified (near-horizontal) and dispersed flow regimes over a wide range of total flow rate and cut. The flow meter may not require that the wellbore be oriented azimuthally in any particular way during installation. The invention also provides a flow meter that avoids the use of relatively strong radioactive sources. It can be capable of detecting small changes in water cut and flow rate and providing a measurement of a phase transition pressure. The invention can also be used to alleviate the problems associated with the use of conventional mixers, including the possible problems associated with measuring the pressure differential upstream and downstream of a conventional mixer.